Wellbore laser operations

ABSTRACT

Methods may include selecting a slot size of apertures to control sand production including formation fines in fluid from a subterranean zone. The slot size may be selected based on a distribution of sizes of particles in fluid from the subterranean zone. A laser may be used to form apertures with the selected slot size in a casing installed in a wellbore in the subterranean zone. Systems and apparatuses may be configured to perform the above operations.

CLAIM OF PRIORITY

This U.S. patent application claims priority under 35 U.S.C. §119(e) toU.S. Provisional Application 61/221,418, filed on Jun. 29, 2009, thedisclosure of which is considered part of the disclosure of thisapplication and is hereby incorporated by reference in its entirety.This U.S. patent application also claims priority under 35 U.S.C. §120to U.S. application Ser. No. 12/825,906, filed on Jun. 29, 2010 thedisclosure of which is considered part of the disclosure of thisapplication and is hereby incorporated by reference in its entirety.

TECHNICAL FIELD

The present disclosure relates generally to stimulating and completing awell in an earth formation, and more specifically, to systems andmethods for stimulation, sand control, perforation, well completion,drilling operations, and near wellbore operations.

BACKGROUND

Once a wellbore has been drilled and one or more zones of interest havebeen reached, a well casing is run into the wellbore and is set in placeby injecting cement or other material into the annulus between thecasing and the wellbore. The casing, cement and formation are thenperforated to enable flow of fluid from the formation into the interiorof the casing.

In the past, the casing, cement and formation have been perforated usingbullets or shaped charges. Both techniques, however, may result in aperforation having a positive skin, i.e. localized decreasedpermeability that reduces the production of formation fluid from theformation into the perforation. It is generally desirable that theperforations have a neutral or a negative skin, i.e. localized increasedpermeability resulting in an increased production of formation fluid. Inaddition, these traditional perforating methods rely on the use ofexplosives, which pose obvious safety, transportation and securityissues.

Known perforating techniques, as well as drilling techniques, do notprovide any analysis of the formation rock being perforated or drilled.More so, there is no known technique for analyzing the chemical elementsand certain other chemical characteristics of formation rock in situ,that is, without removing the rock from the well. Such analysis would behelpful in determining the optimal location and depth for the currentand other perforations, provide in-situ formation evaluation at theperforation site, or on a larger scale, assist in evaluating the currentwell or other wells. Presently, to obtain an analysis of the formationrock being perforated or drilled, a representative sample of theformation rock must be retrieved to the surface and analyzed. Dependingon whether the analysis can be performed on site, such analysis may adddays or even weeks to the well completion. Further, the analysisinvolves material that may have been altered in the process of removingit from the well.

SUMMARY

The present disclosure is drawn to systems and methods of stimulatingand/or perforating that use a laser beam to remove material, such as toperforate the casing, cement and formation. The system and method canfurther or alternately encompass material analysis that can be performedwithout removing the material from the wellbore. The analysis can beperformed apart from or in connection with stimulation operations and/orperforating the casing, cement and formation.

In some implementations, methods can include: characterizing asubterranean formation; selecting an orientation of an aperture based oncharacteristics of the subterranean formation; and using a laser to forman aperture of the selected orientation in the wall of the wellbore. Insome implementations, methods can include: characterizing a subterraneanformation; selecting an aperture shape based on characteristics of thesubterranean formation; and using a laser to form an aperture of theselected shape in a wall of the wellbore. In some implementations,methods can include: selecting an orientation of an aperture based oncharacteristics of the subterranean formation; and using a laser to forman aperture in the selected orientation in the wall of the wellbore.Embodiments of these implementations can include one or more of thefollowing features.

In some embodiments, selecting an orientation can include selecting anorientation aligned to provide greater exposure of the aperture to anaxis of preferred permeability. Selecting an orientation can includeselecting an orientation aligned relative to direction of principalstress in the formation. Selecting an orientation can also includeselecting an orientation to facilitate formation of a fracture thatconnects with a natural fracture.

In some embodiments, using the laser to form an aperture can includeforming an aperture connecting to a pre-existing natural fractureidentified while characterizing the formation. Using the laser to forman aperture can include forming apertures at a location selected forfracture initiation. Forming apertures can include forming a aperturethat extends along the length of the wellbore and is orthogonal to aformation bedding plane. Forming an aperture can include forming aaperture with a first dimension that increases with increasing distancefrom an axis of the wellbore. Using the laser to form an aperture caninclude forming an aperture with negative skin.

In some embodiments, the wall of the wellbore can include a casing andwherein using a laser to form an aperture in a wall of the wellbore caninclude forming an aperture in the casing. Using a laser to form anaperture in a wall of the wellbore can include forming an apertureextending through the casing into the subterranean formation. In someembodiments, the wall of the wellbore can be an open hole and using alaser to form an aperture in the wall of the wellbore can includeforming an aperture in side surfaces of the open hole.

In some embodiments, characterizing a subterranean formation can includecharacterizing a distribution of sizes of particles in the subterraneanformation; and selecting an aperture shape based on characteristics ofthe subterranean formation can include selecting a slot size to filterparticles from fluid in the formation, the slot size selected based onthe distribution of sizes of particles in the subterranean formation.

In some embodiments, methods can include: selecting an aperture shapebased on characteristics of the subterranean formation; and using alaser to form an aperture of the selected shape in a wall of thewellbore. Selecting an aperture shape based on characteristics of thesubterranean formation can include selecting a slot size to filterparticles from fluid in the formation, the slot size selected based onthe distribution of sizes of particles in the subterranean formation.

In some embodiments, the shapes of the apertures have a maximumdimension that is aligned with a principal stress field of theformation. Selecting the aperture shape can include selecting anaperture shape with a longer axis aligned to expose more of theproducing formation than a circular cross-section hole of a similarperimeter.

In some implementations, methods of producing fluids from a wellbore caninclude: communicating fluids through a first aperture in a wall of thewellbore; and after communicating fluids through the first aperture inthe wall of the wellbore, using a laser to seal the first aperture inthe wall of the wellbore. Embodiments can include one or more of thefollowing features.

In some embodiments, methods can include, after communicating fluidsthrough the first aperture in the wall of the wellbore, using a laser toform a second aperture in the wall of the wellbore. Communicating fluidsthrough the first aperture in the wall of the wellbore can includeproducing fluids through the first aperture in the wall of the wellbore.Communicating fluids through the first aperture in the wall of thewellbore can include introducing fluids into a subterranean zone fromthe wellbore through the first aperture in the wall of the wellbore.Methods can include producing fluids through the second aperture in thewall of the wellbore.

In some embodiments, the wall of the wellbore can include a casing andusing the laser to seal the first aperture in a wall of the wellbore caninclude sealing an aperture in the casing. Sealing the aperture in thecasing can include fusing shut apertures in the casing. Fusing shut anaperture in the casing can include heating the casing such that oppositesides of the aperture fuse together or can include selectively lasersintering fusible powders.

In some embodiments, the wall of the wellbore is an open hole and usinga laser to seal an aperture in the wall of the wellbore can includesealing an aperture in side surfaces of the open hole.

In some implementations, methods of producing fluids from a well havingan existing production profile and a specified production profile caninclude: if the existing production profile does not match specifiedproduction profile, receiving location information on apertures selectedto achieve the specified production profile; running a laser tool into awellbore of the well; and operating the laser tool to change a flowdistribution of the wellbore to cause the existing production profile tomore closely match the specified production profile. Embodiments caninclude one or more of the following features.

In some embodiments, operating the laser tool to change the flowdistribution of the wellbore can include forming apertures in thewellbore using the laser and/or sealing apertures in the wellbore usingthe laser. Changing the flow distribution of the wellbore can includebalancing flow along a substantially horizontal wellbore by changing thedistribution of apertures along a substantially horizontal wellbore.

In some embodiments, changing the production profile of the wellboreover time can include producing fluids from one subterranean zone andthen forming apertures to access a second subterranean zone. Methods caninclude sealing apertures providing fluid communication from the firstsubterranean zone to the wellbore.

In some embodiments, a wall of the wellbore can include a casing andsealing apertures of the wellbore can include sealing apertures in thecasing. A wall of the wellbore can be an open hole and sealing aperturesof the wellbore can include sealing an aperture in a side surfaces ofthe open hole.

In some embodiments, forming apertures in the wellbore using the lasercan include selecting an aperture geometry to filter solids from fluidin the formation (e.g., a slot with a slot size selected based on adistribution of sizes of particles in the subterranean formation; andusing a laser to form slots with the selected aperture geometry in acasing installed in the wellbore in the subterranean zone. Selecting theaperture geometry to filter particles from fluid in the formation caninclude selecting the aperture geometry to control sand productionincluding formation fines.

In some implementations, methods of forming a well in a subterraneanformation can include: selecting an aperture geometry to filter solidsfrom fluid in the formation, the aperture geometry selected based on adistribution of sizes of particles in the subterranean formation; andusing a laser to form slots with the selected aperture geometry in acasing installed in the wellbore in the subterranean zone. In someimplementations, methods can include: selecting a slot size of aperturesto control sand production including formation fines in fluid in aformation, the slot size selected based on a distribution of sizes ofparticles in the subterranean zone; and using a laser to form apertureswith the selected slot size in a casing installed in a wellbore in thesubterranean zone. In some implementations, methods can include:selecting an aperture geometry to filter solids from fluid in theformation, the aperture geometry selected based on a distribution ofsizes of particles in the subterranean formation; using a laser to formslots with the selected aperture geometry in a casing installed in thewellbore in the subterranean formation; and producing fluid from thesubterranean formation through wellbore. Embodiments can include one ormore of the following features.

In some embodiments, selecting the aperture geometry to filter solidsfrom fluid in the formation can include selecting an aperture geometryto filter particles from fluid in the formation. Selecting the aperturegeometry to filter particles from fluid in the formation can includeselecting the aperture geometry to control sand production includingformation fines. in particular, selecting an aperture geometry to filterparticles from fluid in the formation can include selecting the aperturegeometry in which the cross-section of individual apertures in thecasing decrease with increasing distance from a central axis of thecasing such that a smallest portion of each aperture is at the outersurface of the casing.

In some embodiments, the subterranean zone can include an unconsolidatedformation and selecting the aperture geometry to filter solids fromfluid in the formation can include selecting an aperture geometry tomaintain structural stability of the unconsolidated formation.

In some embodiments, method can also include, in response to levels ofparticles in fluid being produced through the wellbore, operating thelaser to change a flow distribution of the wellbore. Operating the lasertool to change the flow distribution of the wellbore can include formingapertures in the wellbore using the laser and/or sealing apertures inthe wellbore using the laser. Methods can also include sealing firstapertures extending through the casing and forming second aperturesextending through the casing of the wellbore, the second apertureshaving a different geometry than the first apertures. In some cases, awidth of the second apertures is smaller than a width of the firstapertures.

In some embodiments, selecting the slot size of apertures to controlsand production including formation fines in fluid in the subterraneanzone can include selecting an aperture geometry in which thecross-section of individual apertures in the casing decrease withincreasing distance from a central axis of the casing such that asmallest portion of each aperture is at the outer surface of the casing.In some cases, the subterranean zone can include an unconsolidatedformation and selecting the slot size of the apertures to control sandproduction including formation fines in fluid in the formation caninclude selecting an aperture geometry and distribution to maintainstructural stability of the unconsolidated formation.

In some implementations, methods of installing downhole equipment in awellbore can include: forming a profile in a wall of the wellbore usinga laser; inserting a piece of downhole equipment into the wellbore suchthat a portion of the piece of downhole equipment is aligned with theprofile formed in the wall of the wellbore; engaging the profile formedin the wall of the wellbore with the piece of downhole equipment. Insome implementations, methods of installing downhole equipment in awellbore can include: using a laser to form a recess in an inner surfaceof a casing installed in the wellbore; inserting a piece of downholeequipment into the wellbore; and deploying an extendable dog on thepiece of downhole equipment to matingly engage the recess in the innersurface of a casing of the wellbore. In some implementations, methodscan include: using a laser to form a window extending through a casinginstalled in a wellbore; inserting a piece of downhole equipment intothe wellbore; and engaging the window formed in the wall of the wellborewith the piece of downhole equipment. Embodiments can include one ormore of the following features.

In some embodiments, forming the profile can include forming a femaleprofile in the wall of the wellbore. Forming the female profile in thewall of the wellbore can include forming a recess in a casing installedin the wellbore. Forming the recess in the casing installed in thewellbore can include forming a recess that only extends partway throughthe casing. In some cases, the female profile is sized and positioned toreceive extendable dogs on the piece of downhole equipment.

In some embodiments, forming the female profile can include forming anannular recess extending around an inner diameter of the casing. In someembodiments, forming the female profile can include forming multiplediscrete recesses formed at a common distance from an entrance of thewellbore.

In some embodiments, the piece of downhole equipment is a seal, a pump,liner hanger, or a downhole steam generator.

In some embodiments, methods can include inserting the piece of downholeequipment into the wellbore such that the extendable dogs on the pieceof downhole equipment are aligned with the recesses in the surfaces ofthe wellbore; and extending the extendable dogs on the specific piece ofdownhole equipment to matingly engage the recesses in the surfaces ofthe wellbore.

In some embodiments, forming the profile can include forming a windowextending through a casing installed in the wellbore. In some cases, thewindow is sized to receive a junction. Methods can include deploying thejunction into the wellbore such that the junction is aligned with thewindow; and inserting the junction into and extending through thewindow. In some cases, methods can include sealing the window afterinserting the junction into and extending through the window.

In some embodiments, electric wirelines incorporating downhole laserscan be used in place of or in addition to conventional methods ofsetting and/or unsetting downhole tools such as setting/unsetting withweight, setting/unsetting using tubular-supplied hydraulics, orsetting/setting with wireline through the use of explosives. Similarly,in some embodiments, electric wirelines incorporating downhole laserscan be used in place of or in addition to conventional methods offreeing stuck downhole tools such as using tubulars in a fishingoperation or drilling to remove the tools. The use of electric wirelinewith a downhole laser for these operations can be faster and often moreprecise. Other electric wireline tools can be combined with the laser toprovide data telemetry, retrieval or setting heads, depth correlation,and electric controls.

An advantage of some of the implementations is that they may enable atleast one chemical characteristic of an earth formation to be determinedwithout removing the formation or the analysis tool from the wellbore.Therefore, chemical analysis can be performed during a single trip ofthe drilling string, tubing string or wireline into the wellbore.Multiple locations (both axially and circumferentially) in the wellborecan be analyzed during the same trip. In the case of drilling orperforating, the analysis can be performed without having to remove thedrilling or perforating equipment, and the analysis can be performedconcurrently with the drilling or perforating processes. Such concurrentanalysis enables more frequent sampling of the formation, as well as,more ready use of the formation information in drilling or perforating.

An advantage of some of the implementations is that material can beremoved or analyzed in two or more locations substantially concurrently.

An advantage of some of the implementations is that material can beremoved or heated in specified patterns, for example, circumferentialgrooves or conical perforations.

An advantage of some of the implementations is that increasedpermeability (negative skin) develops in the formation in the area ofthe material removed.

An advantage of some of the implementations is that perforations may bemade without the use of explosives.

An advantage of some implementations is that techniques based on the useof electric wirelines with downhole lasers can remove the requirementfor explosives to be shipped to location and run into the hole. Thesetechniques can also reduce the likelihood that sensitive tools such aspressure sensors and other data gathering sensors are damaged during,for example, tool setting using explosives. In addition, thesetechniques can provide the ability to run and retrieve downhole toolswith electric line with very accurate depth correlation.

An advantage of some implementations is that downhole lasers can be usedto glaze or resurface surfaces downhole. In some instances, afterextended periods of hydrocarbon production, this can provide a newmethod of remediating pitting, erosion or other damage that can occur inthe surfaces of downhole tools due to incompatibility between the flowconstituents of production flow stream and the type of metallurgy usedto make the downhole hardware and/or due to other reasons. Being able toglaze/resurface devices downhole can save considerable expense(work-over rig costs and non-producing time) and get the wells to returnto production more quickly.

An advantage of some implementations is that lasers can be used to cutwindows for lateral completions including multilateral completions.Laser cutting of casing may provide improved lateral windows as comparedto milling of windows for lateral completions.

In some implementations, laser glazing operations can provideimprovements to a metal surface such as hardening of the metal surface,smoothing the metal surface, decreasing the friction coefficient of thesurface, and increasing corrosion resistance of the metal surface. Laserglazing, particularly in downhole applications, can provide much higherefficiency than chemical treatments used to try and achieve at leastsome of the same effects. For downhole oilfield operations, the metalsurface improvements provided by laser glazing may enhance multi-lateralmilling, drilling, and completion operations. In addition, productionequipment may be more cost effectively treated to allow continuedproduction without equipment replacement.

In some implementations, the combination of downhole laser tools andassociated downhole video and/or thermal imaging cameras can providehighly efficient devices for freeing tools which are stuck downhole.Normally, impediments to stuck tools downhole require fishing operationswith tubulars. These tubulars often encounter difficulty engaging thetop of the tools or difficultly freeing the tools once engaged. Downholevideo has been used to define the obstruction or configuration of thetop of the tool. This requires a separate trip into the wellbore for thevideo, then customized drilling or fishing devices are run in ontubulars to remove the impediment or reconfigure the top of the tool toallow for proper fishing tool engagement. Much of this work is trial anderror and may require several trips with the video camera. By combininglaser with the video and/or thermal imaging operation the impedimentscan be removed in a single trip.

In some implementations, downhole laser tools and operations can be usedto remove and/or consolidate formation material downhole to control thedegree of communication from the wellbore to the formation.Consolidation may also be achieved or enhanced by selective lasersintering of heat-fusible solids unto the wellbore surfaces. Selectivelaser sintering may be carried out by depositing a layer of aheat-fusible powder onto surface. Heat-fusible powders include ceramics,metals, and plastic polymers such as ABS plastic, polyvinyl chloride(PVC), polycarbonate, and other polymers. The laser beam heats thepowder and sinters the particles into a solid surface. A second layer ofpowder may be deposited on the sintered surface and again treated withthe laser. In this manner, the sintered surface may be built up layer bylayer. In some cases, a single sintered layer may be sufficient to forma sufficiently consolidated surface. In addition, certain filter cakeformulations may be applied to the wellbore surface during drillingoperations. Laser irradiation may be used to further enhance the filtercake such that the wellbore surface is consolidated. These consolidationprocesses can reduce the amount of fines produced over time. As the samelaser can be used to form perforations in the formation, bothperforation and formation treatment can be performed in one downholetrip instead of the multiple trips for perforation and formationtreatment required today.

Forming perforations using downhole laser tools and methods iscompatible with many wireline tools; can be used to provide precisionperforations (e.g., clean and highly precise cuts in terms of length,width and depth) on previously installed casing; and can be used inconjunction with technology such as gamma ray logging, casing collarlocation and/or other technology. This approach can achieve more preciseplacement and sizing of perforations than explosive shape chargeperforating and hydrajetting. Moreover, this approach does not inducecompaction damage to the target rock.

In some implementations, lasers can be used to initiate explosives, suchas those used in explosive-based perforating guns used in perforatingwellbore casings and/or subterranean formations and/or in otheroperations. Since a laser is used to detonate the explosives, there isno possibility of electrical interference. Only firing of the laser willfire the explosives. No radio silence or other restrictions on the useof electrical equipment during perforating operations are required. Thiscan provide increased safety for personnel onsite as well as reducedchances of accidentally perforating out of zone due to electricalinterference. In addition, the elimination of electrical interferenceissues opens the possibility of combining adding electric conductors tothe fiber in the wireline cable so that one can run logging tools duringperforating runs. This may enable a savings in rig time due to theability to combine logging and perforating in a single run.

The details of one or more embodiments of the invention are set forth inthe accompanying drawings and the description below. Other features,objects, and advantages of the invention will be apparent from thedescription and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic of downhole tool system.

FIG. 2 is a side cross-sectional view of an illustrative laser tooldepending from a wireline and depicted perforating a wellbore.

FIG. 3 is a side cross-sectional view of an illustrative laser tooldepending from a tubing string and depicted perforating a wellbore.

FIG. 4 is a schematic of a downhole tool system with a wireline.

FIG. 5 is a schematic of a downhole tool system with a coiled tubingstring.

FIG. 6A is a side cross-sectional view of the illustrative laser tool ofFIG. 2 showing different trajectories of the laser beam.

FIG. 6B is a cross-sectional view of FIG. 6A along section line B-Bshowing different trajectories of the laser beam.

FIG. 6C is a cross-sectional view of an alternate illustrative lasertool showing different trajectories of the laser beam typical indrilling a vertical wellbore.

FIG. 6D is a cross-section view of another alternate illustrative lasertool showing different trajectories of the laser beam achieved using afiber optic array.

FIGS. 7A-7I is a series of side cross-sectional views illustrating thesequence of a laser-initiated treatment process.

FIGS. 8A-8C is a series of side cross-sectional views illustrating aportion of the sequence of a laser-initiated treatment process.

FIGS. 9A and 9B are schematics of a laser set packer.

FIGS. 10A and 10B are schematics of a laser released packer.

FIGS. 11A-11C is a series of schematic side views illustrating adownhole laser-glazing process.

FIG. 12 is a schematic view of a laser-initiated detonation.

FIGS. 13A and 13B are, respectively, an axial cross-sectional schematicand a transverse cross-sectional schematic of a liner hanger in awellbore.

FIG. 14 is a schematic of a junction in a wellbore.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

Downhole laser tools and techniques can be used to enhance communicationbetween a wellbore and a subterranean formation, to provide adequateflow paths, to reduce potential fluid flow restriction due to formationdamage, to allow for more precise design for radial flow into or out ofa formation, and to implement stimulation treatments for enhancing fluidflow such as acidizing, sand control or hydraulic fracturing treatments.Downhole laser tools can be deployed, for example, with wireline ortubing (coiled and/or jointed) and is compatible with wellboreconfigurations without internal diameter restrictions. Perforationtechniques can be used to create specific size or geometry foropening(s), from large holes or slots to allow solids such as proppantparticles to enter easily, to narrow slots in casing that would allowsignificant fluid flow into or out of the wellbore while preventingproduction of solids such as formation sand and proppant. Theperforation techniques may be combined with high pressure pumping tocreate a larger opening and/or to stimulate the formation. For example,laser operations may be performed to perforate and/or initiate afracture in concert with high pressure pumping operations.

Downhole laser tools and techniques also can be used other applications.For example, downhole laser tools and techniques can be used to treatthe surface of downhole equipment in situ; to set and release downholeequipment; to consolidate formation material; and to initiateexplosives, such as those used in perforating wellbore casings and/orsubterranean formations.

Once a wellbore has been drilled into a formation and casing is setinside the wellbore, communication between the formation and theinterior of the well casing is through openings (i.e., perforations)created through the casing and (if present) cement filling the annulusbetween casing and the formation. The perforations may be through thecasing material only, also through an annular fill (such as cement) andstop at formation face, or they may penetrate to some depth into theformation. The perforations may be in the form of approximately circularperforations, elongated slots and/or other shapes.

Referring to FIG. 1, an illustrative downhole tool system 200 for use ina wellbore 10 includes a laser source 29 on the surface, a deploymentsystem 210 (spooled, cable, coiled tubing, jointed pipe, etc.), and alaser tool 20. The deployment system 210 can include an umbilical 27(e.g., cable or tubing (coiled or jointed) with cable on the innerdiameter) that, for example, contains optical fibers and/or otherwaveguide elements used to controllably transmit light from the surfaceto the laser tool 20. A laser beam 26 (e.g., a high intensity laserbeam) can be transmitted from the laser source 29 via a transmissionline 27 (e.g., a wireline containing an optical fiber) to the laser tool20. The downhole tool system 200 can include a mechanism for achievingproper orientation in the wellbore relative to formation properties orother geometric consideration such as depth or direction and/orextendable stabilizers such as those discussed in more detail in U.S.Pat. Pub. No. 2006/0102343, incorporated herein by reference. Thedownhole tool system 200 can also include an anchoring system (e.g.,slips, collets, and/or matching profiles in the tool system 200 andsurrounding tubular, such as the casing) for fixing the laser tool 20 inposition in the wellbore 10. After the laser tool 20 is temporarilyanchored in the wellbore 10, an on-board system such as those discussedin more detail below for moving and adjusting the position of andcharacteristics of the laser beam can precisely control thecharacteristics of the directed laser beam 26 such as, for example, theposition, cutting depth, and impingement angle. This system can allowvery specific and precise entry into the formation from the wellbore tobe achieved. In some instances, the laser source 29 can be providedwholly or partially downhole.

Referring to FIGS. 2 and 3, the wellbore 10 is illustrated as a casedwellbore in a formation 12 that has a casing 14 affixed therein. A layerof cement or similar material 16 fills an annulus between the casing 14and the wellbore 10. An embodiment of the laser tool 20 is depicted inuse perforating the wellbore 10. The illustrative laser tool 20 isadapted to be inserted into the wellbore 10 depending from a wireline 18(FIGS. 2 and 4) or a tubing string 19 (FIGS. 3 and 5), and to direct thelaser beam 26. Although depicted as removing material from the formation12 to form a perforation 22, the laser tool 20 can be adapted to also oralternatively drill a new wellbore or extend an existing wellbore. Asdiscussed in more detail in U.S. Pat. Pub. No. 2006/0102343,incorporated herein by reference in its entirety, the laser tool canalso be adapted to heat material to emit light for use in laser inducedbreakdown spectroscopy (LIBS). In addition, a non-destructive laserspectroscopic methods may be used, optionally in combination withdrilling and/or stimulation operations, to interrogate formationproperties by spectroscopic analysis of the reflected light.

As the illustrative laser tool 20 of FIGS. 2 and 3 is depictedperforating a cased wellbore 10, it is directing the laser beam 26 ontothe casing 14, the cement 16, and the formation 12. The illustrativelaser tool 20 and related concepts described herein are equallyapplicable to an “open hole” wellbore. An open hole wellbore is one inwhich at least a portion of the wellbore has no casing. Furthermore, thelaser tool 20 may be used in perforating or drilling through variousequipment installed in a wellbore, and is not limited to perforatingthrough casing, cement layers, and formation. When referring to a wallof a wellbore herein, the wall can include any interior surface in thewellbore, such as a sidewall or end/bottom wall thereof.

The downhole deployment system 210 can include of a spool 212 for theumbilical (e.g., wireline 18 in FIG. 4 or coiled tubing string 19 inFIG. 5). In some embodiments, as shown in FIGS. 4 and 5, such lasersources 29 can be small enough to mount on the inner surface of thespool 212 holding the wireline 18 or coiled tubing string 19. Mountingthe laser in the spool eliminates the need for rotary optical couplersconnecting the cable on the spool to the laser because the laser source29 moves with rotation of the spool 212.

In some embodiments, the laser tool 20 and cable can be carried downhole by a mobile device such as for example, a wireline deployedself-propelled robotic device (e.g., well tractor), rather than ontubing or the cable alone. This technique may have advantages inhorizontal or highly deviated wells. In this approach, the tractor actsas the slips to anchor the tool in position and rather than moving thetool with a hydraulic section, the tractor can controllable move thelaser tool 20 when extending an initial perforation. For example, long,continuous slots can be formed by activating the laser tool 20 while thewell tractor moves the laser tool 20 along the well bore.

Power and/or signals may be communicated between the surface and thelaser tool 20. Wireline 18 may include one or more electrical conductorswhich may convey electrical power and/or communication signals. Wireline18 may additionally or alternatively include one or more optical fiberswhich may convey light (e.g. laser) power, optical spectra, and/oroptical communication signals. Neither the communication of power, norsignals to/from the surface, are necessary for the operation of theimplementations. In lieu of such communication, downhole batteriesand/or downhole generators may be used to supply the laser tool 20power. A downhole processor may be employed to control the laser tool20, with relatively little (as compared to wireline) or no communicationfrom the surface. For example, instructions for performing operationsmay be preprogrammed into a processor installed in the laser tool 20before running the laser tool 20 into the wellbore 10 and/or the lasertool 20 may respond to simple commands conveyed via surface operationssuch as rotary on/off, relatively low data rate mud-pulse,electromagnetic telemetry, and acoustic telemetry communication.

In implementations incorporating a tubing string 19, the tubing may becontinuous tubing or jointed pipe and may be a drilling string. Thetubing string 19 may incorporate a wireline 18 as described above.Tubing string 19 may be “wired drill pipe,” i.e. a tubing havingcommunication and power pathways incorporated therein, such as the wireddrill pipe sold under the trademark Intellipipe by Grant Prideco, Inc.The tubing string 19 may contain a smaller tubing string within forconveying fluids such as those used in the fluid based light pathdescribed below or for conveying chemicals used by the laser.

In addition to waveguides to transmit laser light from the surface todownhole, the umbilical may also contain optical fibers and sensors tomeasure the temperature distribution of the umbilical along its length.These measurements can be used to detect hot spots where the umbilicalmay be damaged and deteriorating as a result of damage. By identifyingdamaged or abnormally hot sections of the umbilical, a potentiallydangerous umbilical breach or umbilical failure may be avoided.Additionally under normal operations, it would be desirable to know thetemperature distribution of the umbilical in order to help insure thatthe umbilical is operated only under specified conditions which can tohelp provide a long service life.

The laser tool 20 can also include other features such as, for example,an extendable light path and/or a snorkel as described in more detail inU.S. Pat. Pub. No. 2006/0102343.

The laser tool 20 can control the timing, direction, focus and power ofthe laser beam 26. Different light patterns can be applied by varyingthe timing (i.e. pulsing), direction, focus, and power of the laser beam26 depending on the type of materials to be removed, treated, oranalyzed, for example, the casing 14, the cement 16 and different typesof rock in the formation 12. Accordingly, in removing material, thelaser beam 26 light patterns can be adjusted to crack, spall, melt, orvaporize the materials to be removed and change as the material typechanges. The laser beam 26 can be configured to remove material in asingle continuous pulse or multiple pulses. The multiple pulses may becyclical, such as in a duty cycle. The power of the laser beam 26 can beselected such that the duty cycle necessary to remove the material inthe desired manner (crack, spall, melt or vaporize) is less than 100%.In most instances of removing material during perforating operations,the laser beam 26 is directed on the formation with a duty cycle thatcauses the rock to chip or spall. Laser beam/tool configurationsincluding pulse strategies are discussed in more detail in U.S. Pat.Pub. No. 2006/0102343.

In FIGS. 2 and 3, the illustrative laser tool 20 includes a laser beamdevice 24. The laser tool 20 may optionally be provided with a focusingarray 28 through which the laser beam 26 passes. Additional detailsregarding focusing arrays and their operation are discussed in moredetail in U.S. Pat. Pub. No. 2006/0102343.

The laser beam device 24 may relay the laser beam 26 generated remotelyfrom the laser tool 20, such as generated by a laser source 29 on thesurface and input into the laser beam device 24 via a transmission line27 (FIG. 3), such as an optical fiber or light path. In someembodiments, rather than relaying a laser beam generated at the surface,the laser beam device 24 generates the laser beam 26. In suchembodiments, the laser beam device 24 may be, for example, anelectrical, electro-chemical laser or chemical laser, such as a diodelaser or an excimer or pulsed Na:YAG laser, dye laser, CO laser, CO₂laser, fiber laser, chemical oxygen iodine laser (COIL), or electricdischarge oxygen iodine laser (DOIL). In some implementations it may bedesirable to use a DOIL to increase service intervals of the laser tool20, because a DOIL does not substantially consume the chemicals used increating the laser beam and the chemicals need not be replenished for anextended duration. It is to be understood that the examples ofparticular lasers disclosed herein are for illustrative purposes and notmeant to limit the scope of the claims.

Additionally, the laser tool 20 can include hydraulic channels runningthrough the laser tool 20 so that fluid pumped around the cable can passthrough the laser tool 20. Such fluid can provide a liquid purge formaintaining a relatively clean light path from the laser tool 20 to theformation, can help remove debris and cuttings produced by the action ofthe laser, and can cool the laser tool 20. In an embodiment, a gas and aliquid purge may be used in combination to remove debris and cuttingsproduced by the laser. By way of example, referring to FIG. 3, window 54may be modified such the window may be opened to form an aperture.Optionally the aperture may be fitted with an extension channel fittedto the outer wall of laser tool 20. Gas may be pumped down the tubingstring 19 to provide a clear path for the laser beam 26. At the sametime, a liquid purge may be pumped down the annular space between thetubing string 19 and the casing 14 to remove debris and cuttings. Insome embodiments, the laser tool 20 can be made to rotate along itslongitudinal axis to move the beam in an arc or circle around thewellbore.

Some or all of the components of the laser tool 20 can be encased in ahousing 52. The housing 52 can have one or more windows 54 adapted toallow passage of the laser beam 26 out of the housing 52 and emittedlight 36 into the housing 52. The size and shape of the windows 54accommodate the aiming capabilities of the laser beam 26 and receipt ofemitted light 36. The windows 54 are further adapted to withstand theelevated pressures and temperatures experienced in the wellbore 10. Someexamples of materials for constructing the windows 54 may be glass,silica, sapphire, or numerous other materials with appropriate opticaland strength properties. The windows 54 may have anti-reflectioncoatings applied to one or both surfaces to maximize the transmission ofoptical power therethrough while minimizing reflections. The windows 54may comprise a plurality of optical fibers positioned to direct thelaser beam 26 or collect emitted light 36 from multiple locations aboutthe wellbore 10. For example the optical fibers may be fanned radiallyabout the laser tool 20.

Although the laser beam device 24 can be oriented to fire directlytowards the material being removed or heated in one or moretrajectories, the illustrative laser tool 20 is configured with thelaser beam device 24 firing into a reflector 30. The reflector 30directs the laser beam 26 toward the formation 12 and may be operated toassist in focusing the laser beam 26 or operate alone in (when nofocusing array 28 is provided) focusing the laser beam 26 into thematerial being removed. In the illustrative laser tool 20 of FIGS. 2 and3, the laser beam 26 is directed substantially longitudinally throughthe laser tool 20 and the reflector 30 directs the laser beam 26substantially laterally into the wellbore 10. The laser tool 20 can beconfigured to fire the laser beam 26 in other directions, for example,down.

The laser beam 26 may be directed to remove material or heat variouspoints around the wellbore 10 and in varying patterns. In anillustrative laser tool 20 having a reflector 30, the reflector 30 canbe movable in one or more directions of movement by a remotelycontrolled servo 32 to control the direction, i.e. trajectory, of thereflected laser beam 26. In a laser tool where the laser beam device 24fires directly into the formation 12 or in a laser tool having areflector 30, the laser beam device 24 can be movable by control servoto control the trajectory of the laser. In lieu of or in combinationwith a reflector 30, the laser beam can be directed into the formation12 using a light path (see FIG. 6D, discussed below), such as a fiberoptic, that may optionally be movable by control servo to control thetrajectory of the laser beam. The light path may include multiple paths,such as a fiber optic array, that each direct the laser beam in adifferent trajectory. The multiple paths can be used selectively,individually or in multiples, to direct the laser beam in differenttrajectories.

In the illustrative example of FIGS. 2 and 3, the laser beam 26 isdirected using the reflector 30 and control servo 32, rather than or incombination with moving the laser tool 20. The control servo 32 can beconfigured to move the reflector 30, at least one of, about alongitudinal axis of the wellbore 10 (see FIG. 6A), about a transverseaxis of the wellbore 10 (see FIG. 6B), or along at least one of thelongitudinal and transverse axis of the wellbore 10. FIG. 6A depicts thelaser tool 20 firing the laser beam 26 through angle α about thewellbore longitudinal axis. Depending on the application, it may bedesirable to configure the laser tool 20 so that angle α may be as muchas 360°. FIG. 6B depicts the laser tool 20 firing the laser beam 26through angle β about the wellbore transverse axis. Depending on theapplication, it may be desirable to configure the laser tool 20 so thatangle β may be as much as 360°. The laser tool 20 can be appropriatelyconfigured so as not to fire the laser beam 26 upon itself. FIG. 6Cdepicts an illustrative laser tool 20 firing in multiple trajectories,through angle φ, typical for drilling a vertical wellbore 10. Dependingon the application, angle φ may be as much as 360° and may be orientedthrough 360° polar about the longitudinal axis of the laser tool 20.

FIG. 6D depicts a illustrative laser tool 20 that uses a light path 104comprised of multiple optical fibers 106 each oriented to fire in adifferent trajectory. The laser beam 26 may be directed through all ofthe multiple optical fibers 106 substantially simultaneously, or may bemultiplexed through the multiple optical fibers 106, for example, as afunction of duty cycle as is described below. Likewise, emitted lightcan be received through the multiple optical fibers 106 for use inmaterial analysis as is described herein. Although depicted with aspecified number of optical fibers 106 arranged vertically, the numberand pattern of the optical fibers 106 can vary. For example, only oneoptical fiber 106 can be provided. In another example, the pattern inwhich the optical fibers 106 are arranged can additionally oralternatively extend circumferentially about the laser tool 20 to reachcircumferential positions about the wellbore 10. The arrangement ofoptical fibers 106 can be configured to produce specified patterns inthe material removed, heated, and/or analyzed.

By directing the laser beam 26 relative to the laser tool 20, withreflector 30, light path 104, or otherwise, the laser tool 20 can remainin a single position (without further adjustments or reorientation) andremove or heat material in multiple locations around the wellbore 10.Accordingly, the number of adjustments and/or orientations of the lasertool 20 during an entire operation is reduced. Physically moving thelaser tool 20 is time-consuming relative to adjustment of the lasertrajectory using the configurations described herein (ex. by movingreflector 30). Therefore, the ability to reach multiple trajectorieswithout moving the laser tool 20 reduces the amount of time necessary toperform operations (drilling, perforating, formation analysis,stimulating).

According to the concepts described herein, the laser beam 26 can bemanipulated with multiple degrees of freedom and focal points to removematerial in many different patterns. For example, standard geophysicalinvestigation techniques can be used in characterizing a subterraneanformation to observe formation characteristics such as permeability,principle directions of stress, the size distribution of particles inthe formation, and/or formation fracturing characteristics. Theorientation and/or shape of the aperture(s) in the wall of a wellborecan be selected based on characteristics of the subterranean formation.

The orientation of the aperture(s) can be selected with an alignment toprovide greater exposure of the aperture(s) and/or induced fracture(s)initiated at the aperture(s) to an axis of preferred permeability. Sofor example, a slice or thin wedge can be removed from the wall of thewellbore 10, orthogonal to and along the length of the wellbore 10, andorthogonal to a formation bedding plane, with a larger thickness at itsdistal end from the wellbore 10, and exposing far more formation surfacethan traditional perforating operations.

Aperture shapes and orientations can be selected based on the locationof natural fractures in the formation. For example, apertures can beformed connecting to a pre-existing natural fracture identified whilecharacterizing the formation. In some cases, an orientation of theapertures can be selected to facilitate formation of a fracture thatconnects with a natural fracture. The laser can be used to formapertures at a locations selected for fracture initiation. In somecases, the orientation of the apertures can be selected with anorientation aligned relative to direction of principal stress in theformation. The orientation of the apertures can be parallel to,orthogonal to, or at a specific angle relative to the direction ofprincipal stress in the formation. The shapes of the apertures can havea maximum dimension that is aligned relative to a principal stress fieldof the formation. Selecting the aperture shape can include selecting anaperture shape with a longer axis aligned to expose more of theproducing formation than a circular cross-section hole of a similarperimeter.

The distribution of sizes of particles in the subterranean formation canalso be an used in selecting the shape and size of apertures beingformed in a wellbore. For example, in a sandy formation, aperture shapescan be selected as slots with a slot size chosen such the slots beingformed in a well casing filter particles from fluid in the formation.Larger apertures may be selected in a coal seam where the casing is usedto prevent formation collapse rather than to filter out fine particlesfrom fluid being produced from the formation.

The concepts described herein enable a perforation hole to be shaped(such as by providing slots, rather than tubes or pits) to minimizefluid pressure down-draw. Multiple shapes can be envisioned within theimplementations which may promote hydrocarbon recovery rate, totalrecovery and efficiency.

In the illustrative laser tool 20, the laser beam 26 can be directed toremove or heat material circumferentially about the wellbore 10 byactuating the control servo 32 to rotate the reflector 30 about alongitudinal axis of the wellbore 10 and/or actuating the reflector 30to move along the transverse axis of the wellbore 10. The laser beam 26can be directed to remove or heat material along the axis of thewellbore 10 by actuating the control servo 32 to rotate the reflector 30about a transverse axis of the wellbore 10 or move along thelongitudinal axis of the wellbore 10. The laser beam 26 can be directedto remove or heat material in an area that is larger than could beremoved in a single trajectory, by actuating the reflector 30 to rotateabout and/or translate along at least two axes, for example thelongitudinal and transverse axis. The laser beam 26 would then bedirected in two or more different trajectories to substantially adjacentlocations on the material being heated or removed. For example, bydirecting the laser beam 26 to project on the material being removed orheated at quadrants of a circle, the laser beam 26 can substantiallyremove or heat the material in a circular shape. By directing the laserbeam 26 in two or more trajectories at the same location, the laser tool20 can remove material to form a conical perforation having a largestdiameter at the opening or having a smallest diameter at the opening.Also, the laser beam 26 may be directed in one or more trajectories toform a perforation in the earth formation, and concurrently whileforming the perforation or subsequently, be directed in one or moretrajectories to widen the perforation. The laser beam 26 can also bedirected in two or more different trajectories to remove or heatmaterial of the earth formation in a substantially continuous area ortwo or more disparate areas.

The laser being directable can be also be use to drill more efficientlyand/or with unique hole characteristics, as compared to both the classicdrill-bit drilling and prior non-directable laser drilling. In drillingwith the laser beam 26, the laser beam 26 would be directed axiallyrather than radially, and the laser beam tool 20 would be conveyed onthe bottom of the bottom hole assembly in place of the drilling bit (seeFIG. 6C). A circular path could be swept by the laser beam 26, cutting(for example by spalling) a thin annular hole, approximately equal to adesired hole diameter. The resulting “core” sticking up in the middlewould be periodically broken off and reverse circulated up the wellbore10, for example up the middle of the drill string 19, to the surface.Accordingly, the laser energy is being used only to cut a small amountof rock (i.e. the annular hole). The same laser beam 26 directingconfigurations discussed above in the context of perforating could beapplied to drilling. Because the material removal is not resulting froma mechanical bit being rotated, a circular cross-section hole is notnecessary. For example, the laser beam 26 could be directed to sweep outelliptical, square, or other hole shapes of interest.

Using the directionality of the material removal allows formation ofspecified perforation section shape(s) that can provide enhancedproduction. For example, the perforations can be formed in arectangular, oval, elliptical, or other hole section with a longer axisaligned to expose more of the producing formation than a circularcross-section hole, or aligned to provide greater exposure to an axis ofpreferred permeability, or preferential production (or non-production)of oil, water, gas, or sand. In another example, aperture geometry canbe selected based on a distribution of sizes of particles in thesubterranean formation to filter solids from fluid in the formation, theaperture geometry. Solids can range in size. The solids can be largepieces such as discrete chunks fractured from the body of a coal seamand small particles such as sand and formation fines. In some instances,the cross-section of individual openings in the casing can decrease withincreasing distance from a central axis of the casing such that thesmallest portion of each opening is at the outer surface of the casing.In unconsolidated formations, the aperture geometry and distribution canbe selected to maintain structural stability of the unconsolidatedformation.

Such specified perforation section shape(s) may provide wellbore orperforation stability. For example, a rectangular, oval, or ellipticalshape can be employed with a longer axis aligned with the principalstress field of the formation, for increased stability and reducedtendency of collapse as compared to a circular cross-section hole.Moreover, if the formation rock is stable, the openings may be cutdeeply into the formation, thus creating negative skin (enhanced flowpotential) and enhancing formation fluid production or fluid injection.

In some well designs, evenly distributed openings arranged around thecircumference of the wellbore can be formed by either removing allcasing material for some width or by leaving some casing material inplace. These openings can be repeated across the height of the formationor along the length of the wellbore if the wellbore is not vertical.This scenario works very well for a formation that is fairly isotropicwith no immediate plan to use hydraulic fracture stimulation.

If the formation is to be hydraulically fractured, the openings could becreated in a desired direction with respect to formation rock stresses,such as in the direction of the maximum stress. The openings can besized to allow the desired flow of proppant laden fluid (unrestricted,or with a specific desired degree of slurry flow restriction). Usinglasers to etch deep into the formation can significantly lower thepressure required for formation breakdown and also can lower thefracture propagation pressure.

If the formation is known to be anisotropic or naturally fractured, thelocation of the openings may be designed to take advantage of theformation properties or specific geomechanics present. For example,stress anisotropy is defined as a condition existing in a formationwhere there is a higher stress in one direction. In rock mechanics,these stresses are given three dimensions—x-y referring to thehorizontal directions at 90 degrees orientation and the z direction inthe vertical orientation.

For a conventional perforated well,Pb=3σh−σH+Tensile strength of the rockwhere Pb is the breakdown pressure (i.e., the pressure necessary toinitiate a fracture in rock by applying hydraulic force; σh is theminimum horizontal stress; and σH is the maximum horizontal stress. Fora laser perforation with a perforation tunnel length of six times thewellbore radiusPb=σh+Tensile strength of the rockFor a laser slotted perforation configuration, where the effective areaof the perforation tunnel is increased substantially with a six inchpenetration into the rock and a six inch vertical penetration:Pb=σh+Tensile strength of the rockThus, laser perforations in general can result in a lower pressurenecessary to initiate a fracture in rock by increasing the area of rockexposed to the hydraulic force such that the hydraulicpressure×perforation area equals the force applied to the rock toinitiate the fracture.

In addition, the ability to precisely locate perforations being formedby laser tools can make it easier to locate openings to coincide withthe higher permeability areas of the formation. Since, for a laserperforation that is oriented in such a way to connect to an exposedpre-existing natural fracture as determined by logging information:Pb=σhThis can further reduce the pressure necessary to initiate a fracture inrock. Various logging, seismic, and/or micro-seismic techniques such as,for example, triple combo logging based on a combination of resistivity,bulk density, and porosity measurements; magnetic resonance imaging; anddipole sonic logging can be used to locate exposed pre-existing naturalfractures. The laser tool 20 is then positioned to form perforationsaccessing these natural fractures.

In wellbores that are not cased, or cased but have no annular fill forsealing material, laser cuts that penetrate the formation can create a“zone of weakness” at the selected location to enhance the probabilitythat fracture initiation from a frac treatment would occur at theselected location(s), whereas conventional shape charge perforatingmethods may actually increase resistance to fracture initiation by thesevere compaction of the formation material that occurs using thatperforation process. Additionally, lasers can be used to create or fuseshut slotted liner sections “in-situ”. Selective laser sintering offusible powders may also be used to close slotted liner section“in-situ”. One advantage of doing this is that slotted liner sectionscan be created selectively after standard casing has been run and casedhole logs used to determine where liner slots should be placed. Thiswould eliminate the need for intricate space-out of liner sections whiledeploying the liner.

In some instances, the general sequence of laser initiation of astimulation/fracturing treatment proceeds as illustrated in FIGS. 7A-7J.A section of wellbore to be stimulated is illustrated in FIG. 7A. Thedownhole tool 214 including slips 216 and packer 218 is run in the holeon a jointed pipe (see FIG. 7B) before the laser tool 20 is run downholeon the cable and landed and sealed in the downhole tool (see FIG. 7C).Next, the slips 216 are set as shown in FIG. 7D. In some cases, theslips 216 of the downhole tool 214 can be set prior to running the lasertool 20. The laser light (denoted as the dotted arrows) is transmitteddown the cable, collimated or focused, and directed toward the formationwith a reflector 30 (see FIG. 7E). As described above with reference toFIG. 6A, the reflector 30 may be movable in order to control thedirection of the beam.

Additionally, fluid can be pumped from the surface along the cable,through channels in the laser tool 20 and outward, coaxially with thelaser energy. The stream of fluid can provide several advantages. First,the fluid can move debris and other materials removed by the laser awayfrom the beam. Second, the fluid can help maintain a clear, low opticalloss path between the laser tool 20 and the inner surface of thewellbore. Finally, the flow of fluids from the surface can cool thelaser tool 20 and the cable.

In general, the fluid is chosen for its optical clarity so as tominimize the disruption of the focused laser beam. The efficiency of afluid-based light path is a function of the optical transmissionefficiency of the fluid. To increase the efficiency of the fluid-basedlight path, a fluid having a high optical transmission efficiency at thewavelength of the laser beam 26 or emitted light 36 can be selected.Water, certain oils, and mixtures or solutions including water and/oroil, are among many efficient optically transmissive fluids that can beused for the fluid-based light path. While water and oil are bothliquids, the fluid need not be liquid. For example, the fluid-basedlight path could be a gas, such as nitrogen at high pressure. Theabsorptivity of the fluid for the laser and LIBS Spectrum wavelengthsshould be taken into account during the selection of the fluid used inthe light path. In an embodiment, a gas such as nitrogen at highpressure may be used with a liquid to allow a clear path for the laserbeam.

The density of the fluid, as well as the speed at which it is expelledfrom the laser tool 20, may be selected to reduce the influence ofoutside factors on the path of the fluid-based light path. For example,as the drilling mud circulates through the wellbore 10, it can entrainthe fluid-based light path, and, in the case of a light path that isdirected substantially perpendicular to the wall of the wellbore 10,shift the light path to impact the wall at an angle and at a differentlocation that originally aimed. Likewise, impacts with largerparticulate in the drilling mud may attenuate or deflect the light pathfrom its trajectory. Such deflection and shift can be reduced by jettingthe fluid at a high speed or even ultrasonic speed and/or by choosing afluid that is dense. The density of the fluid, be it water, oil, orother, can be increased, if so desired, with a weighting agent, such ascesium salt, which can result in a mixture which has acceptabletransparency. Additionally, the circulation of fluids through thewellbore 10 can be ceased during operation of the laser tool 20, or thelaser tool 20 can be operated when circulation of fluids would otherwisebe ceased, for example, while adding joints of pipe in the normaldrilling process.

The influence of outside factors on the path of the fluid-based lightpath can also be reduced by reducing the distance the light path mustspan between the laser tool 20 and the material being removed oranalyzed. The distance can be reduced by providing the outlet throughwhich the fluid-based light path is expelled close to the material beingremoved or heated, for example, by selection of the laser tool 20diameter to be close to the diameter of the wellbore 10 and/or provisionof the outlet in a stabilizer fin. To the degree the fluid based lightpath does shift or deflect, if the light path remains continuous or anybreak in the light path is insignificant, the laser beam 26 or emittedlight 36 will still follow the path and be transmitted between thematerial being removed or analyzed and the laser tool 20.

However, for subterranean wellbores, the medium within the wellboreprovides functions such as, for example, well control, bit lubrication,pipe lubrication, sloughing control, cuttings transport and removal,temperature regulation, pressure regulation and other specializedfunctions. As optical clarity is not a typically requirement forwellbore media, a majority of traditional wellbore fluids (i.e.,drilling muds) do not readily transmit light and are inappropriate forthe downhole laser applications. However, other medium which normallyhave been used in specialized applications (both on surface and in thesubsurface) are candidates for this application. Some fluids useful forthis purpose include, for example, fresh water, inorganic salt brines,or soluble viscosifiers. Acids (e.g., acetic acid, hydrochloric acid,formic acid, citric acid or combinations thereof); gases (e.g.,nitrogen, natural gas, and carbon dioxide), and oils (e.g., mineral oil,gasoline, xylene, and toluene) can also be used.

For example, some saltwaters including but not limited to sodiumchloride, potassium chloride, ammonium chloride, calcium chloride,sodium bromide, calcium bromide, zinc bromide, potassium formate, andcesium formate saltwaters can have a level of light transmissibilitythat can permit the transmission of a laser beam in a subterraneanenvironment. These saltwaters span the density range from 8.3 ppg to 22ppg. The density range is important in that as the density of fluidimpacts the hydrostatic pressure used for well control (i.e., to balancethe subterranean pressure from the different strata). It can beadvantageous use fresh water and some saltwaters because these fluidscan be left in the wellbore and/or formation after use.

In another example, a variety of viscosifing agents can also provide aclear medium for transmission of light. Specific examples of agents thatprovide a clear medium for transmission of light include but are notlimited to polysaccharide-hydroxyethyl cellulose (HEC) (commerciallyavailable as Halliburton Product WG-17), carboxymethyl hydroxypropylguar (CMHPG) (commercially available as Halliburton Product WG-18),hydroxypropyl guar (HPG) (commercially available as Halliburton ProductWG-11), biopolymers such as xanthan (commercially available asHalliburton Product WG-24, WG-37, and BP-10) and diutan, and derivatizedHEC (commercially available as Halliburton Product WG-33). Examples ofagents that, properly prepared and/or filtered can provide a clearmedium for transmission of light include but are not limited toTerpolymer (commercially available as Halliburton Product FDP-S906-08)and guar gum (commercially available as Halliburton Product WG-11,WG-19, WG-22, WG-26, WG-31, WG-35, WG-36). In some embodiments, thefluid may absorb the laser energy and vaporize to provide a clear pathfor the laser beam. Vaporization of the liquid along the laser beam pathmay assist in removal of debris and cuttings from the actions of thelaser. Minimizing the fluid path length of the laser beam, for example,by extendable devices may be advantageous in the use of liquid fluids toremove debris and cuttings.

The viscosifing agents can suspend and “sweep” away residual drillcuttings which could otherwise block the transmission of the laser beam.These agents can also increase the viscosity of the fluid in thewellbore which can help limit the loss of fluid (leak off) to theformation and can help to maintain a constant and consistentsubterranean environment. In addition, because most of these fluids canbe used with a variety of saltwaters, they can provide a wide range ofdensities which make them more useful for well control applications.

Carbon Dioxide is a gas at standard temperatures and pressures. When itreaches its super critical state (87.9° F. (31.1° C.) and 1070.6 psia(7.38 mpa)), carbon dioxide acts as both a liquid and a gas and, as acolorless liquid, can have good light transmission properties.

Acids are often used in subterranean environments for their abilities todissolve and remove unwanted materials or objects. Acids which can havesufficient light transmissivity to be used with downhole laser toolsinclude but are not limited to HCl, HF, acetic, citric, and formicAcids. Acid solutions can also provide a reactive medium to assist inthe operation of the laser to produce the desired material removaleffects.

Certain petroleum distillates can provide a high level of opticalclarity which would permit the operation and transmission of a laserbeam. Petroleum distillates include but are not limited to xylenes,butanes, etholenes, tolulenes, propane, terpine and various otherfluids. Certain products like propane would typically be gaseous butunder pressure and temperature constraints can be made into a liquid.These liquids are often beneficial as solvents.

Laser tools 20 using fluid-based light paths are discussed in moredetail in U.S. Pat. Pub. No. 2006/0102343.

After the laser has been on, an initial perforation 22 is made as shownin FIG. 7E. In order to extend the perforation 22, the hydraulic systemin the downhole tool 214 moves the laser tool 20 vertically relative tothe stationary slips 216 at a controlled rate. This motion while thelaser is on extends the perforation 22 into a slot as shown in FIG. 7F.

At this point, it may be possible to reposition the downhole tool 214without removing the laser tool 20 and repeat the steps shown in FIGS.7D-7F to make multiple slots without withdrawing the laser tool 20 tothe surface. However, if the downhole tool 214 is run on jointed pipe,one will only be able to move the downhole tool 214 with the laser tool20 in place the length of the pipe joint. If joints need to be added orremoved from the string, the laser tool 20 will need to be retrieved tosurface before adding or removing joints and run back in to continuecutting.

The laser tool 20 can be withdrawn to the surface (see FIG. 7G) beforethe packers 218 are set (see FIG. 7H), and the stimulation treatmentcommenced (see FIG. 7I). In some cases, the packer(s) 218 will not berequired for stimulation and the downhole tool may be removed and thestimulation treatment pumped from the surface.

Referring to FIGS. 8A-8C, in some embodiments, the downhole tool 214 andlaser tool 20 are combined on the end of coiled tubing such that one canmake multiple cuts over a wide range of depths by repeatedly performingthe illustrated steps and repositioning the coiled tubing betweeniterations. After the perforations are formed, the coiled tubing can beremoved and the stimulation treatment can be pumped downhole.Alternatively, the coiled tubing can be left in place and the treatmentpumped downhole outside of the coiled tubing. Additionally, the additionof a bypass valve in the coiled tubing string that routes stimulationfluids around the laser tool (e.g., routing flow from the bore of thecoiled tubing into the annulus and/or otherwise bypassing the lasertool) can allow one to pump the stimulation fluids through the coiledtubing with the downhole tool 214 and laser tool 20 and cable in place.Thus, in some instances, hydraulic fracturing operations conducted onmultiple interval completions can take advantage of laser perforatingdeployed with coiled tubing or wireline to conduct the fracturingoperations sequentially without the need to trip in and out of thewellbore between treatments to perform the perforating operations.

If the laser tool 20 is mounted on the end of a coiled tubing unit, itcan be run in the well and the laser and purge fluid can impinge on afixed location to effect a simple, round perforation. The laser tool 20can be rotated in the well bore if desired to make multiple round,azimuthally distributed perforations at a single depth. The coiledtubing mounted laser tool 20 can then be repositioned to perforate at adifferent depth. Simple laser perforating can be accomplished with thecable conveyed laser tool 20 and downhole tool.

In another application, laser tools can be used to activate setting andreleasing mechanisms in downhole tools apart from or together withweight, tension, or explosives. The tools can be conveyed into positionby wireline or jointed or coiled tubing and then set in place by using adownhole laser tool. For example, a downhole laser can be used to heatfluid in a sealed chamber to provide hydraulic force necessary toactivate the setting or unsetting mechanism in the tool. In anotherexample, a downhole laser can be used to cut an element to releasestored energy provided by a spring mechanism within the tool. Similarly,the same technique can be used to provide a release mechanism forretrieving these tools. Use of these techniques to set and/or releasetools provides operations that do not require explosives or speciallyrun tubulars. In addition, if sensitive tools (such as pressure gauges,fluid sensors, etc.) need to be placed precisely in a wellbore, the useof laser activated tools provides a ‘softer’ set mechanism as well ascompatibility with other wireline tool components that provide depthcorrelation and telemetry for data retrieval.

In some embodiments, a laser can be generated at the surface andconveyed through a fiber-optic cable (e.g., as part of an electricwireline cable) to a pressure vessel attached to a downhole tool. Thelaser can be used to heat fluid in the pressure vessel to providehydraulic force capable of shifting a tool to a set or unset positionfor the purpose of setting or retrieving the tool with wireline.

FIGS. 9A and 9B illustrate use of this technique to set a packer 218.The packer 218 is run into the well with the slips 216 and sealingelements 220 retracted. Once the packer 218 is located at the desireddepth, a laser tool 20 is lower into the well to a position adjacent toa fluid filled chamber 222 in the packer tool. The fluid in the chamber222 expands and exhibits increased pressure when heated sufficiently.The laser beam heats the fluid in the chamber caused fluid expansion andincreased volume. The pressure is transferred through a floating piston224 to another chamber 226 which contains a hydraulic oil. The hydraulicoil passes through a check valve 228 and acts upon a hydraulic ram 230which compresses a sealing element 220. The sealing element 220transfers the axial load to the slip loading ram 232 which drives theslips 216 out against the casing. The packer remains set because thecheck valve 228 prevents the hydraulic oil from flowing back into theoil chamber 226 once the laser beam is removed an the expansive fluidcools down. This concept can be used with any tool which requiredactuation downhole. For example, other common tools that can be set orreleased using this technique include, for example, bridge plugs, andanchors for sensors such as pressure, rate, temperature, micro-seismic,and/or tilt-meters; ‘kick-off’ plugs, oriented re-entry ports formulti-laterals, and baffles.

In some embodiments, the laser can be used in conjunction with settabletools to cut elements within the tool to release springs or otherresilient members that would provide the stored energy to activate thesetting mechanism and disengage the wireline from the set tools.Alternatively, when tools require retrieval the laser can cut through aretaining mechanism within the tool that would allow removal of the toolwith wireline.

FIGS. 10A and 10B show a laser released packer. In this embodiment, amechanical element which maintains the integrity of the packer set isremoved with a laser thus causing the packer to become unset. A lasertool is lowered into the wellbore until it is properly aligned with therelease element 234 within the packer. The release element holds themechanical load placed on the setting mandrel 230 during setting of thepacker 218. This load is carried by the setting mandrel 230, the sealingelement 220, the slip ram 232, and the slips 216 which “bite” into thecasing. The laser beam is then turned on and the release elements 234are removed causing the mechanical load on the packer to be relieved,thus allowing the packer to un-set. This type of release mechanism canbe used on any tool which has a secondary position which is held inplace by a mechanical element. This same method can be used to initiatea set or other downhole tool movement by releasing a spring or opening ahydraulic path which causes a change in position in a downhole tool.

In another application, downhole lasers can be used to glaze orresurface surfaces downhole. In some instances, the glazing can beperformed after extended periods of hydrocarbon production.

For example, in some instances, the production flow stream containssolids that pit or erode a surface (e.g., a surface of a downhole tool).If the chemical nature of the flow constituents is unknown or notproperly planned for, the flow-wetted surfaces may begin to deterioratevery quickly due to incompatibility between the flow constituents andthe type of metallurgy used to make the downhole hardware. Being able toglaze/resurface the necessary downhole devices in place can saveconsiderable expense (work-over rig costs and non-producing time) andget the wells to return to production more quickly.

Certain wells require stimulation to produce at economic rates. Thestimulation treatments can be performed at any time during the life ofthe well. It is not uncommon for wells to receive multiple stimulationsover the course of a number of years. The fluids and components of thestimulation systems can be erosive, corrosive, or both. Downhole lasertools can be used to perform downhole glazing to repair damage createdfrom the stimulation fluids placed into the wellbore and/or damage thatmay have occurred when the remnants of the stimulation fluids flow backthrough the flow-wetted parts of the downhole installation.

Laser glazing of metal surfaces is a process in which the surface of ametal is heated by laser irradiation. As the laser beam passes over thesurface, a micro-surface layer of the metal can be melted. Once thelaser beam moves, the melted micro surface layer can quickly re-solidifyinto a thin surface coating. This surface coating hardens the surfaceand may remove stress cracking (e.g., stress cracking that may beinvolved in the initiation of metal failure). In addition, the surfaceof a metal that has been treated by laser glazing often has a lowercoefficient of friction than the original untreated surface.

Using downhole laser glazing can provide a hardened, smoothed, and morelubricious metal surface and, performed in a downhole environment, has anumber of advantageous applications. For example, the laser glazing ofthe metal surfaces adjacent to/in proximity to lateral wellbores from avertical wellbore (i.e., the “bend” or “heel” section of a deviated orlateral wellbore) provides advantages in horizontal drilling,completions, or work-over operations. In particular, multi-lateraldrilling and completion operations may be enhanced by metal surfacetreatments that provide results achievable by laser glazing; especiallyfollowing an operation such as milling a window in casing. Additionally,such laser glazing may also enhance metal resistance to corrosion.

In subterranean wellbores, horizontal drilling and horizontalcompletions sometimes require lateral milling through the casing of awellbore to allow the subsequent drilling and completion of a lateralfrom that wellbore. For example, this may occur in cases where theprimary wellbore is vertical, inclined, or horizontal in nature. In atypical window milling operation, a casing whipstock is set and used toguide a casing milling tool. After the casing milling operations arecomplete, the milling tools are removed and, in some cases, a drillingwhipstock can then be placed for guidance of the drilling operationthrough the milled window. In the drilling of the lateral, the initialangle of deviation is typically on the order of 5 to 10 degrees.However, even with these small angles of deviation, drilling collars mayrub and wear on the casing sections above the milled window andhardening of this area can reduce wear. Thus, it is desirable thatmaterial at the junction is relatively soft for easier millingoperations. Subsequently hardening and smoothing this area can reducewear during subsequent drilling and completion operations when themilled window is being utilized.

Referring to FIGS. 11A-11C, laser glazing can be used in lateralmilling, drilling, and completion operations. For example, as shown inFIG. 11A, a window can be milled through the casing of a wellbore 10.Although illustrated as a vertical wellbore, the wellbore 10 can beinclined or horizontal in nature. After window 236 has been milledthrough the casing of the wellbore 10, a downhole laser tool 20 can beused to glaze interior surfaces of the casing of the well bore for adistance D1 above the window 236 as shown in FIG. 11B. The downholelaser can be deployed on wireline or (coiled and/or jointed) tubing. Thedistance D1 can be approximately 100 feet (e.g., more than 25 feet, morethan 50 feet, more than 75 feet, less than 200 feet, less than 150 feet,and/or less than 125 feet). The downhole laser tool 20 can then bewithdrawn from the well bore 10 and lateral well bore drilled throughthe window 236. The downhole laser tool 20 can then be deployed into thelateral well bore to glaze a casing of the lateral well bore for adistance D2. The distance D2 can be approximately 20 feet (e.g., morethan 5 feet, more than 10 feet, more than 15 feet, less than 50 feet,less than 40 feet, and/or less than 30 feet). Laser glazing of thecasing about 100 feet above the junction and glazing of the lateralstinger provides hardened surfaces with reduced wear and friction suchthat lateral drilling and completion operations are enhanced.

Referring to FIG. 11B, laser-formed coatings such as ceramic, polymer,metal, or other coatings may be applied to the inner surfaces of thecasing for distance D1 wherein D1 can be approximately 100 feet (e.g.,more than 25 feet, more than 50 feet, more than 75 feet, less than 200feet, less than 150 feet, and/or less than 125 feet). Referring to FIG.11C, laser-formed coatings such as ceramic, polymer, metal, or othercoatings by be applied to the inner surfaces of the casing for distanceD2 wherein D2 can be approximately 20 feet (e.g., more than 5 feet, morethan 10 feet, more than 15 feet, less than 50 feet, less than 40 feet,and/or less than 30 feet). Such laser-formed coating may be applied byselective laser sintering of fusible-powders.

In some instances, the laser tool can be used to form the windowextending through a casing installed in a wellbore. After the window isformed, a piece of downhole equipment can be inserted into the wellbore;and engaged to the window. For example, the laser can be used to form awindow sized to receive a junction. The junction is then deployed intothe wellbore such that the junction is aligned with the window; andinserted into and extending through the window. The window can be sealedafter the junction is inserted into and extending through the window.FIG. 14 illustrates a junction inserted in a window formed in a casingin a wellbore.

Typically subterranean wellbores are designed to be functional formultiple years and decades. The wellbore hardware is constructed basedon the anticipated future flow of fluids (e.g., oil and water), gas(e.g., natural gas), and occasionally solids (e.g., sand and/orformation materials). However, should there be a significant change tothe flow constituents, the flow nature and characteristics may exceedthe original design parameters of the downhole hardware. Examples ofproduction changes that can negatively impact downhole hardware include:increasing solids content leading to increasing erosion and pitting; theintroduction of sulfide reducing bacteria (SRB) into the reservoir whichcan turn the product sour and cause the steel of the hardware to crack;and increasing water flow creating scale deposition. When this occurs,the normal process has been to mobilize a rig, attempt to remove theexisting downhole hardware and replace it with more appropriate hardware

This process can be a very expensive series of operations. There is asignificant risk that well will not be able to return to the same levelof production after the replacement is complete. In addition, theremoval of the existing downhole hardware may be very difficult and timeconsuming, and it may not be possible to physically remove the hardware.Downhole laser glazing can be used to change the surface characteristicsof the flow-wetted downhole hardware (e.g., production packers,mandrels, gas lift mandrels, sand control screens, control valves,sliding sleeves, and production tubing) to provide new characteristicsintended to be more appropriate to the new flow regime.

Normal well operations such as setting packers and perforating can alsocause surface damage and increased susceptibility to corrosion anderosion in high wear areas within a well casing. Each time a packer orother downhole tool is “set” in the casing, biting action of the slipscan damage the casing. The same sections of a casing (e.g., a sectionnear a perforation through the casing) are often used repeatedly forsetting packers and/or other downhole tools. In time, such high-usesections of the casing become very worn and damaged. Laser glazing canbe used to enhance these high-wear/high-use areas and/or to smooth andrepair these areas.

In addition, selective laser sintering of fusible-powders (metal,ceramic, polymer, or fusible powders) can be used to modify, build-up,or repair the surfaces of downhold hardware and/or casing.

Additionally, laser glazing/treatment following perforation of casingcan smooth and harden the surface of the perforated casing and holes toreduce erosion and corrosion in the areas damaged during perforation.

Laser glazing operations can provide improvements to a metal surfacesuch as hardening of the metal surface, smoothing the metal surface,decreasing the friction coefficient of the surface, and increasingcorrosion resistance of the metal surface. Laser glazing, particularlyin downhole applications, can provide much higher efficiency thanchemical treatments used to try and achieve at least some of the sameeffects. As noted above, for downhole oilfield operations, the metalsurface improvements provided by laser glazing may enhance multi-lateralmilling, drilling, and completion operations. In addition, productionequipment may be more cost effectively treated to allow continuedproduction without equipment replacement.

Downhole laser operations can also be used in combination with downholevideo and/or thermal imaging camera observation of the laser operations.For example, downhole lasers and video can be used in combination toremove impediments to downhole tools. A laser generated at the surfacecan be conveyed downhole to a moveable targeting device through a fiberoptic cable embedded into a electric line cable. The same cable can alsoinclude a fiber optic cable for the purpose of providing downhole videocapability with a camera at the end of the cable in juxtaposition to thelaser targeting device. Thus, the operator would have surface control oflaser cutting at a remote, downhole location. In regions where videocamera images may be impeded, thermal imaging cameras may be used toguide laser operations. Thermal imaging sensors may also be used incombination with video cameras to evaluate laser cutting or weldingoperations to assist in control of the laser beam (power, direction, andother laser operational parameters.

Downhole laser tools and operations can also be used to control thedegree of communication from the wellbore to the formation (e.g., adownhole laser tool can be used to remove and/or consolidate formationmaterial downhole). For example, a laser may be used downhole to removeand/or consolidate formation material. The laser can have variable powerlevels to achieve varying effects. The laser might be used toconsolidate the wellbore to enhance borehole stability and, in effect,make an in-situ casing. A low power setting might be used to perforate asubterranean formation and then a high power setting might be used toconsolidate the interior of the perforation tunnel. Varying powersettings, durations, and sequences can be used to vary the properties ofthe consolidated rock from completely impermeable to very permeable.Other combinations of power, duration, sequences, and transmissionmaterials can be used to change the structure of the consolidatedformation in the range from vitrified to crystalline.

Materials might be used downhole prior to, during, or after the lasertreatment to further modify or enhance the properties of theconsolidated rock such as strength or permeability. For example, afilter cake may be created by pressure pumping below fracturing rates.When exposed to the laser, the filter cake can be solidified to enhancethe mechanical strength of the rock. In another example, a material(e.g., a fusible ceramic particulate) can be added to a liquidtransmission medium which would interact with the consolidation processsuch that the permeability of the consolidated rock was changed. Thisconsolidation process can reduce the amount of fines produced over time.As the same laser can be used to form perforations in the formation,both perforation and formation treatment can be performed in onedownhole trip instead of the multiple trips for perforation andformation treatment required today.

In another downhole application on of laser technology, lasers can beused to initiate explosives, including explosives of explosive-basedperforating guns for perforating wellbore casings and/or subterraneanformations. Traditionally, wireline conveyed explosives are electricallyinitiated. This mature technology is susceptible to EM and other radioor electrical interference which may cause the explosives to fireprematurely, sometimes with catastrophic results.

Referring to FIG. 12, a laser detonator includes an optical fiber 240 inthe logging cable. This fiber 240 is capable of transmitting fairlylarge amounts of laser power. Light exiting the end of the fiber isfocused through a conventional lens 242 or alternatively, a curvedmirror through a transmissive window 244 to heat a small volume oftemperature sensitive material 246 such as, for example, titaniumsubhydride potassium perchlorate (THKP). Heating of the THKP causes thedetonation of an adjacent volume of an explosive 248 such as, forexample, high melting explosive (HMX) which is used to initiatedetonating cord 250 connected to a conventional explosive train to firethe perforating guns.

Since a laser is used to detonate the explosives, there is nopossibility of electrical interference of any sort. Only firing of thelaser will detonate the explosives. No radio silence or otherrestrictions on the use of electrical equipment during operations arerequired. This can provide increased safety for personnel onsite as wellas reduced chances of accidentally perforating out of zone due toelectrical interference. The elimination of electrical interferenceopens the possibility of combining adding electric conductors to thefiber in the wireline cable so that one can run logging tools duringperforating runs. This may enable a savings in rig time due to theability of combining logging and perforating in a single run.

In some embodiments, a laser can be used to ignite a explosivepropellant for the wireline setting of packers and bridge plugs. Forexample, the HMX in FIG. 12 can be replaced with a propellant thatactivates a wireline setting tool such as, for example, a Baker 20wireline tool. This can be significantly quicker than heating up a fluidto pressure set a tool as described with respect to FIGS. 9A and 9B.

In another downhole application on of laser technology, laser tools canbe used to adjust the flow parameters of a well that has been inproduction. For example, fluids can be communicated through a firstaperture in a wall of the wellbore. The fluids can be pressure fluidsbeing used to frac a formation, fluids being produced from asubterranean formation through the wellbore, and/or fluids such as steambeing introduced into the subterranean formation from the wellbore.

After communicating fluids through the first aperture in the wall of thewellbore, a laser can be used to seal the first aperture in the wall ofthe wellbore. In some instances, the wall of the wellbore includes acasing and the laser is used to seal an aperture in the casing. Theaperture can be sealed by fusing shut apertures in the casing (e.g., byheating the casing such that opposite sides of the aperture fusetogether) or by selectively laser sintering fusible powders (e.g.,fusible powders disposed in the aperture). In some instances, the wallof the wellbore is an open hole and using a laser to seal an aperture inthe wall of the wellbore includes sealing an aperture in side surfacesof the open hole (e.g., by glazing the surface of hole extending into asubterranean formation to reduce the local permeability of the formationin the vicinity of the hole). The laser can also be used to form asecond aperture in the wall of the wellbore which can be used, forexample, to producing fluids from the subterranean formation.

This approach can be applied to heavy oil formations in which it isdesirable to reduce the viscosity of oil in a subterranean formation.Steam can be introduced into the subterranean formation through firstapertures in the wall of a wellbore. A laser tool can then be used toseal the first apertures. The laser tool can then be used to open otherapertures in the wall of the wellbore. These second apertures can beformed, for example, at locations spaced apart from the locations wherethe first apertures were previously found. Alternatively oradditionally, these second apertures can be formed at the same locationwhere the first apertures were previously found but with a differentgeometry (e.g., shape and/or distribution) than the first apertures.

This approach can also be used to adjust the production profile of awell. For example, a well can having an existing production profile anda specified production profile. If the existing production profile doesnot match specified production profile, location information onapertures selected to achieve the specified production profile can bereceived. A laser tool can be run into a wellbore of the well andoperated to change a flow distribution of the wellbore to cause theexisting production profile to more closely match the specifiedproduction profile. Operating the laser tool to change the flowdistribution of the wellbore can include forming apertures in thewellbore using the laser and/or sealing apertures in the wellbore usingthe laser.

For example, in response to the upcoming of underlying water near theheel of a horizontal well, apertures near the heel of the substantiallyhorizontal wellbore can be sealed and additional apertures can be formedat the far end of the horizontal wellbore. Thus, the laser tool can beused to change the distribution of apertures along a substantiallyhorizontal wellbore to balance flow along the substantially horizontalwellbore.

In another example, after producing fluids from one subterranean zone,apertures can be formed to access a second subterranean zone. In someinstances, the apertures providing fluid communication from the firstsubterranean zone to the wellbore can be sealed.

In another downhole application on of laser technology, laser tools canbe used in the installation of downhole equipment in a wellbore. Thelaser can be used to form a profile (e.g., a female profile) in a wallof the wellbore. A piece of downhole equipment (e.g., a seal, a pump,liner hanger, or a downhole steam generator) can be inserted into thewellbore and the profile formed in the wall of the wellbore can beengaged with the piece of downhole equipment.

The female profile in the wall of the wellbore can be a recess in acasing installed in the wellbore (e.g., a recess that only extendspartway through the casing). The female profile can be sized andpositioned to receive extendable dogs on the piece of downholeequipment. The female profile can include an annular recess extendingaround an inner diameter of the casing or multiple discrete recessesformed at a common distance from an entrance of the wellbore to set thelocation of the piece of downhole equipment along the wellbore. In someinstances, the female profile includes a keyway or multiple keyways tolimit the rotation of the piece of downhole equipment after it is set inplace with the extendable dogs on the piece of downhole equipment arealigned with and extended to matingly engage the recesses in thesurfaces of the wellbore.

FIGS. 13A and 13B are schematics illustrating the use of a femaleprofile comprising multiple discrete recesses to suspend a liner hangerin a wellbore. Although shown as vertical, the wellbore could have otherorientations (e.g., be slanted or horizontal). The recesses extend onlypartway through a casing in the wellbore. Four equally spaced dogs areextended to engage the recesses to hold the liner hanger in place. Othernumbers of recesses and dogs can be used in other embodiments of thesystem.

Various configurations of the disclosed systems, devices, and methodsare available and are not meant to be limited only to the configurationsdisclosed in this specification. Even though numerous characteristicsand advantages have been set forth in the foregoing description togetherwith details of illustrative implementations, the disclosure isillustrative only and changes may be made within the principle of theinvention. Accordingly, other embodiments are within the scope of thefollowing claims.

What is claimed is:
 1. A method comprising: selecting a slot size ofapertures to control sand production including formation fines in fluidfrom a subterranean zone, the slot size selected based on a distributionof sizes of particles in the subterranean zone; using a laser to formapertures with the selected slot size in a casing installed in awellbore in the subterranean zone; and sealing apertures in the wellboreusing the laser to change a flow distribution of the wellbore inresponse to levels of particles in fluid being produced from thewellbore.
 2. The method of claim 1, wherein selecting the slot size ofapertures to control sand production including formation fines in fluidfrom the subterranean zone comprises selecting an aperture geometry inwhich the cross-section of individual apertures in the casing decreasewith increasing distance from a central axis of the casing such that asmallest portion of each aperture is at the outer surface of the casing.3. The method of claim 2, wherein the subterranean zone comprises anunconsolidated formation and selecting the slot size of the apertures tocontrol sand production including formation fines in fluid in theformation comprises selecting an aperture geometry and distribution tomaintain structural stability of the unconsolidated formation.
 4. Themethod of claim 1, further comprising operating the laser to change theflow distribution of the wellbore by forming further apertures in thewellbore using the laser.
 5. A method comprising: selecting a slot sizeof apertures to control sand production including formation fines influid from a subterranean zone, the slot size selected based on adistribution of sizes of particles in the subterranean zone; using alaser to form apertures with the selected slot size in a casinginstalled in a wellbore in the subterranean zone; operating the laser tochange a flow distribution of the wellbore in response to levels ofparticles in fluid being produced from the wellbore; and sealing firstapertures extending through the casing and forming second aperturesextending through the casing of the wellbore, the second apertureshaving a different geometry than the first apertures.
 6. The method ofclaim 5, wherein a width of the second apertures is smaller than a widthof the first apertures.